The present invention relates to the treatment of subterranean formations and fluids useful in such treatment. More particularly, the present invention relates to drilling operations and to fracturing operations and their use in the recovery of hydrocarbons from subterranean formations.
In the recovery of fluids such as crude oil or natural gas from subterranean formations, various materials are added to the well bore and/or subterranean formation to improve the efficiency of the well drilling operation, to increase production of the fluids from the formation, or to terminate and seal a non-producing well. These treating agents are generally added above ground and flowed through the well bore to the subterranean formation. Often, these treating agents contain a particulate matter.
After drilling is complete and to stimulate hydrocarbon recovery, it is common to fracture hydraulically the hydrocarbon-bearing formation to provide channels to facilitate the flow of hydrocarbons to the well bore. In fracturing, a fluid is introduced into the well at a rate and pressure sufficient to produce one or more fractures in the formation, or to enlarge or extend existing fractures. The fluid is generally a thickened fluid which contains a particulate material, commonly referred to as a proppant, such as sand, which is deposited in the fractures. The proppant remains in place within the fracture when the fracturing pressure is released to hold the fracture open.
An ideal fracturing fluid would comprise low friction loss in the well bore, low fluid loss in the fracture, high friction loss in the fracture, good proppant suspension capability, resist the temperatures encountered in the fracturing operation, and be easily recovered from the formation and fracture. High viscosity fluids have commonly been employed in order to transfer efficiently fracturing pressures to the rock, thereby tending to generate wide fractures of considerable length as well as to reduce fluid leak-off. In addition, they are capable of suspending large proppants in high concentrations.
A variety of high viscosity fluids have been proposed for use in hydraulic fracturing operations. For example, the fracturing fluid may comprise either a water or an oil-based fluid thickened with a polymer such as galactomannan gum, a cellulosic polymer or a synthetic polymer. Often, in order to effect the necessary increase in fluid viscosity, the polymeric thickeners must be present in relatively high concentrations. In addition, achieving a sufficiently high viscosity necessary for effective fracturing hinders the pumpability of the fluids.
In order to improve the pumpability of such fluids, various methods have been employed to delay the viscosity increase until the fluid is pumped to the desired location in the formation. One such method involves using a polymeric system which employs a delayed cross-linking agent such as a soluble organo-metallic salt. The fluid retains a low viscosity until the polymer is cross-linked by the metal ions. Upon cross-linking, the viscosity of the fluid substantially increases with coincident rheology improvement. Thus, the fluid can be pumped within the well bore at a relatively low viscosity and only at or near the subterranean formation is the polymer cross-linked.
Upon cross-linking, the fluid exhibits the advantageous properties of a thickened fluid. Unfortunately, polymer residues are retained in the formation, when using fluids thickened with a polymer, thereby reducing the effectiveness of the fracturing operation. In addition, a water-continuous fluid often reduces hydrocarbon recovery due to its incompatibility with the material being recovered.
It has been proposed, as another means for improving a fracturing operation, to use fracturing fluids (such as emulsions of water and oil) which are compatible with the existing fluids in the formation. For example, U.S. Pat. Nos. 3,710,865 and 3,977,472 teach using a stabilized oil-in-water emulsion as a fracturing fluid. In these systems, the discontinuous, internal oil phase typically constitutes from 50 to 80 volume percent of the emulsion. The continuous, water-external phase is stabilized by adding a water-dispersible polymeric thickening agent. These systems are relatively expensive due to the large amounts of oil employed. In addition, since a water-dispersible polymeric thickener is commonly employed in relatively high concentrations, the problem with polymer residues in the formation remains. Also, the water continuous phase is seen to be more damaging to the hydrocarbon bearing formation than are oil based fluids.
One method for reducing the amounts of oil while maintaining the benefit of an oil based fluid involves the use of an oil-external emulsion (i.e., a water-in-oil emulsion). To be more cost effective, water-in-oil emulsions should typically comprise less amounts of oil than the traditional oil-in-water emulsions. In addition, water-in-oil emulsions exhibit reduced interaction with unstable formations. However, the water-in-oil emulsions often exhibit extremely high viscosities which result in high friction resistance to their flow down the well bore. Also, upon the addition of sand, sintered bauxite or other proppant, there is a tendency for the water-in-oil emulsions to break or revert to two separate and continuous phases, thereby losing their advantage.
Methods for overcoming the increased friction due to the high viscosity of the water-in-oil emulsions at low temperatures have been proposed. For example, U.S. Pat. No. 3,378,074 describes a technique in which a lubricating annulus of water forms a physical barrier between the viscous water-in-oil emulsion and the well bore. However, this technique requires the use of a special well head equipment and fittings to create the conditions necessary to form an annulus of water. In addition, the problem of emulsion stability remains.
Another method for overcoming high friction pressure experienced in pumping a viscous water-in-oil emulsion is described in U.S. Pat. No. 4,233,165. In the disclosed method, a water-in-oil emulsion in amounts of 30 to 95 percent by volume is dispersed in an aqueous medium to reduce the overall friction pressure of the resultant dispersion to create a (water-in-oil)-in-water emulsion. The complications of this dual step dispersion process are apparent. In addition, the stability of the system is not necessarily enhanced.
U.S. Pat. No. 4,776,966 discloses a water-in-oil emulsion which comprises an emulsifying agent for the water-in-oil and a dispersing agent for the solid particulate matter. Unfortunately, relatively large amounts of both the emulsifying and dispersing agents must be employed. In addition, while large amounts of water are suggested (i.e., up to 90 percent), no more than 15 to 70 percent water is exemplified.
U.S. Pat. No. 5,633,220 teaches a high internal phase ratio water-in-oil emulsion containing an emulsifier selected from the group consisting of (a) a block or graft copolymer of the general formula (A--COOO).sub.m B, where m is an integer of at least 2, A is a polymeric component having a molecular weight of at least 500 and is the residue of an oil-soluble complex monocarboxylic acid and B is a polymeric component having a molecular weight of at least 500 and comprises a water soluble polyalkylene glycol; (b) the reaction product of a polyalk(en)yl succinic anhydride and a polar compound having at least one hydroxyl or amino group; and (c) mixtures thereof. However, the relatively high cost of such surfactants when used as the principal emulsifying surfactant is an economic deterrent to use of such fluids. Also, high internal phase emulsions in which such polymeric emulsifiers are the principal emulsifying surfactant have not proved stable to the addition of sand as a proppant at high shear conditions.
In view of the foregoing deficiencies with the methods for treating subterranean formations, particularly with water-in-oil emulsions, it remains desirable to provide an improved water-in-oil emulsion for treating subterranean formations.